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November 7, 2024

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ERCOT Proposes ‘Multi-metric’ Approach for Reliability Standard

Three years after a deadly winter storm nearly imploded the ERCOT grid, killed hundreds of Texans and caused billions in financial damages after blackouts lasted for days, stakeholders in the Texas market have begun working on a reliability standard that may be stricter than industry norms. 

ERCOT is proposing a “multi-metric” framework that establishes thresholds on three criteria: frequency, duration and magnitude of loss-of-load events.  

Its baseline recommendations would set a loss-of-load expectation (LOLE) frequency of once every 10 years; 14 hours of rolling outages during an event; and no more than 19 GW of load shed to maintain the ability to roll the outages (54584). 

The grid operator said using maximum magnitude as a probabilistic measure addresses a key physical reliability constraint: how many megawatts can be effectively managed at one time for rotating load shed purposes. It included maximum duration because one reliability policy constraint is the acceptable length to customers of an outage event. 

Pete Warnken, ERCOT senior manager of resource adequacy, told the Texas Public Utility Commission during a May 2 technical workshop that after Winter Storm Uri in 2021, it became clear that the industry’s normal one-in-10 LOLE wasn’t enough on its own. He said staff reviewed other grid operators’ reliability standards and dug into background materials to come up with their proposal. 

“One overarching theme became apparent: Simply relying on the 0.1 LOLE industry standard was not acceptable, and any reliability standard for ERCOT needed to expand beyond this single metric,” Warnken said. “There is an expectation for the commission to establish a reliability standard for ERCOT and take action to ensure the reliability and needs of the region are met both in the near and long term.” 

The 2021 storm came 10 years after a less severe cold weather event in 2011. The rolling outages during the week leading up to Super Bowl XLV, played in the Dallas-Fort Worth area, were shorter and less severe than Uri’s. 

“It makes me think that at a basic level, we are hitting that one-in-10 standard, but we’re still getting the massive outages that we want to try to avoid,” Commissioner Jimmy Glotfelty said. “So, semantics. Two massive outages in 20 years, that’s one in 10.” 

The commission and stakeholders generally supported ERCOT’s approach. 

“I think what ERCOT is proposing makes sense,” PUC Chair Thomas Gleeson said, expressing more interest in what market participants had to say. 

“This is probably the most important policy decision this commission is going to make in terms of the impact to the state and reliability for our system,” NRG Energy’s Bill Barnes said, adding that his company “strongly supports” the resource adequacy-based reliability standard. 

“We feel that this is the missing piece of our market structure. For the most important reliability type of our grid, resource adequacy, up to this point it’s been a shoulder shrug and, ‘Let’s just see what we get.’ That’s why this is such an important decision,” he added. 

Katie Coleman, representing Texas Industrial Energy Consumers and its large industrial users, said the standard could be a “useful tool” as a reference point to decisions on whether to increase the offer cap, change the shape of the operating reserve demand curve or add ancillary services. 

“There’s a lot of judgment involved in a reliability standard. It’s extremely imprecise,” Coleman said. “We continue to have concerns about using it as a single reference point to move billions of dollars around through a capacity construct. So that’s our sensitivity, but not the reliability standard in and of itself.” 

‘Reasonable Starting Point’

PUC staff have since filed a memo responding to several points made during the technical conference. It lays out the decision points staff say it needs to prepare a proposal for the reliability standard’s rulemaking.  

The commissioners will use the memo as the basis for discussions during their May 16 and 23 open meetings. A final rule could possibly be published by June 13, and a final PUC vote taken on the rule in August. 

Commission staff said they view ERCOT’s approach to a reliability standard recommendation to be a “reasonable starting point” and that a commission-approved standard is “essential to achieving long-term resource adequacy.” They said setting the LOLE at close to one event every 10 years is a “reasonable benchmark” that alternative values can be compared to.  

“At a minimum, the commission-approved reliability standard should target a level of reliability that is comparable to other markets and regions across the country,” they said in the memo. 

Staff also noted that adopting a reliability standard does not require implementing the performance credit mechanism (PCM), saying it is not the only tool that could be used to meet the standard. They suggested “alterations” to existing ancillary service products, new reliability products or changes to the scarcity pricing signals as other policy options that could be “tailored” to affect reliability standard metrics. 

While staff agreed with using the industry’s one-in-10 LOLE standard, they found setting a firm megawatt value for the 19-GW magnitude metric is not appropriate as it is directly tied to the system’s operational capability. They suggested a 0.25% exceedance probability for magnitude and updating the metric on a predictable, scheduled basis that aligns with future load-shed capabilities.  

Staff also recommended the duration metric be reduced to 12 hours, with a “more relaxed” 1% exceedance probability. They noted ERCOT’s emergency pricing program will kick in after prices have been at the high systemwide offer cap for more than 12 consecutive hours. 

According to ERCOT’s cost analysis, a 0.1 LOLE is not enough to constrain the maximum magnitude to 19 GW; instead, it would require a 0.04 LOLE. The incremental system cost to achieve this increased reliability is between $195 million and $271 million per year above the amount that supports a 0.1 LOLE, staff said. 

ERCOT’s sensitivity variables include using weather years dating back to 1980 to ensure a “robust weather history” is accounted for. It also suggests a retirement assumption of 900 MW over the next several years and using combustion turbines for capacity, as the latter can be converted into any other combination of resource types. 

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AEP Ohio Asks PUCO for Data Center-specific Tariffs

American Electric Power’s Ohio utility is asking state regulators to create new tariffs forcing data center developers to pay for 90 to 95% of their projected electrical demand for their first decade of operation, even if they use less (24-0508-EL-ATA).

AEP Ohio filed the application with the Public Utilities Commission on May 13. Utility President Marc Reitter said in a news release that the company needs that level of commitment to make the investments required to supply the power-intensive facilities being planned in large numbers in its territory, particularly Central Ohio. 

The proposals would apply to new data centers with a maximum monthly demand of at least 25 MW at a single location or mobile data centers, such as cryptocurrency mining operations, with a maximum monthly demand of at least 1 MW. Data centers that already have signed agreements with AEP at the time the proposed tariffs took effect would be subject to its existing general service tariffs, at least initially. 

According to its filing, AEP’s peak demand in Central Ohio is approximately 4,000 MW, and it has signed binding electric service agreements for 5 GW of new data center load to come online by 2030. But more than 50 customers have submitted requests reserving over 30 GW of additional load. 

“AEP Ohio’s current tariffs were not designed to address (and did [not] contemplate) either the current growth curve based on hyperscale data center development or the unique demands for serving this new class of data center customers,” it said. 

There is also no RTO-controlled generation in Central Ohio, so AEP must import power over the 765-kV backbone system. Using existing transmission, the company will be able to import enough power to serve the new data centers with the 5 GW it has committed to, but serving additional data centers would require construction of new lines at great cost and time, it said: 120 miles of 765-kV line would take seven to 10 years and hundreds of millions of dollars to build. 

In March 2023, AEP imposed a temporary moratorium on data center service requests in Central Ohio so it could analyze the likely impact of future data centers. It will keep the moratorium in place until its proposal is resolved. 

The utility argued in its filing that state law requires it to serve all customers in its service territory, but not in a way that would be unreasonable or impose unjust risk for the company or its other customers. 

Data centers would be billed for the greater of 90% of their contracted capacity or the highest previously established billing demand in the preceding 11 months. That would increase to 95% for mobile data centers.  

The proposed tariffs would also: 

    • require contracts for an initial term of at least 10 years; 
    • include an exit fee for customers that leave early; 
    • impose security and collateral provisions determined by AEP to protect against customer bankruptcy or other failure to meet financial commitments; 
    • impose technical requirements such as a ban on intentionally or unintentionally cycling load in a way that unbalances system frequency; and 
    • mandate participation in the PJM Emergency Demand Response Program and in any emergency event declared by AEP Ohio, with potential service disconnection if the customer does not respond. 

In its request, AEP said it expects data centers to hold at least the top five spots on its list of largest customers by 2030. 

“AEP Ohio has helped the state of Ohio attract thousands of new jobs and billions of dollars in investment because over the decades, AEP has built an extensive network of transmission lines to deliver the power these customers need,” Reitter said in the company’s statement. “This is one of the reasons data center developers targeted Central Ohio, and they continue to request large amounts of power. We need to ensure they can follow through with their commitments as significant new investments are made to serve them.” 

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PJM General Session Covers Risk Management, Innovation

BALTIMORE — Panelists during the General Session at PJM’s Annual Meeting last week focused on the evolving security and climate risks the electric industry faces, as well as the potential for technology and a culture of creativity to provide new solutions. 

Delivering the keynote speech, Elisabeth Braw, senior fellow at the Atlantic Council’s Scowcroft Center for Strategy and Security, said hostile geopolitics are clashing with a globalized economy, putting companies across the world at risk of being caught in the crossfire. 

Because cybersecurity threats are global and often have more to do with national policies than the actual targets, she said individualized efforts at preparation can go only so far. Instead, she recommended organizations work together to identify vulnerabilities and share strategies. 

That coordination often should include the public as well: One mistake Braw said many working in critical infrastructure make is being too tight lipped about the risks they face and their mitigation efforts. She pointed to the cyberattack that interrupted Colonial Pipeline operations in 2021, saying the impacts of the attacks were manageable but that an underinformed public began panic-buying gas and compounding constraints on the pipeline. 

Braw was joined on a panel about the intersection of risk management with national and world events by NERC Vice President Manny Cancel and Paul Williams, president of the Electric Infrastructure Security (EIS) Council. The panel was moderated by PJM Chief Risk Officer Carl Coscia. 

Cancel said joining a regional information sharing and analysis center (ISAC) can allow smaller organizations, such as municipal electric providers, to develop the broad expertise and awareness that large utilities often hold. 

Williams said resilience is possible only through working with the communities an organization is part of. Understanding which services are most important to customers, and which business functions are needed to maintain those services, is key. As the former head of the Bank of England’s Operational Risk and Resilience Division, he said ATMs may seem like a core need, but what truly is important to users is access to cash — an understanding that creates opportunities for building resilience even if ATM networks are disrupted. 

Turning to climate risks, Cancel said the largest challenges are the siting, permitting and interconnecting of new generation and harmonizing the clean energy transition with reliability needs. 

Maintaining the infrastructure the grid requires now and throughout the transition will require honest conversations with the public about what the costs will be, Williams said. 

Innovation Potential and Challenges

Another panel on applied innovation largely focused on the double-edged sword of the rising capabilities of artificial intelligence. 

Jonathan Glass, acting deputy director for commercialization at the U.S. Department of Energy’s Advanced Research Projects Agency — Energy (ARPA-E), said AI could speed research into new storage and generation technologies — as well as improve the process for interconnecting them — but the electric industry first will need to get over the hump of rapidly increasing load growth over the next few years as data centers come online. 

Arshad Mansoor, CEO of the Electric Power Research Institute (EPRI), said AI development is in the “first mile of a marathon” that could see unprecedented load growth over the next few years, potential business that could flow to other nations if the electric sector cannot keep up. He said the next three to four years will be the most important in laying that groundwork, which will have to involve expanding load flexibility while new generation and transmission are built. 

“The country, the region that can power this infrastructure will win the AI race,” he said. 

Mansoor said there’s a disconnect between the personnel working in the electric industry and on the data center side and that more understanding between the two is needed. Forecasting data center demand is changing constantly as computational needs increase and breakthroughs are made in the efficiency of hardware. 

Consumer behavior also could be part of the solution, said Arushi Sharma Frank, principal of Luminary Strategies, such as creating virtual power plants using electric vehicle batteries, home storage systems and smart meters to reduce load during peak periods and shift it to more economical times. 

Perfecting such technologies will require creative thinking and data analytics skills, Frank said, a pairing that is in demand across industries. Loosening regulations around hiring and immigration could allow individuals working overseas to contribute. 

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FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote

FERC issued Order 1920, its long-awaited final rule on long-term regional transmission planning and cost allocation, during a special meeting May 13, but it could not fulfill hopes for a unanimous vote (RM21-17). 

The order requires regional transmission planners, including ISOs and RTOs, to plan at least 20 years ahead of time using multiple scenarios while taking into consideration seven benefits:  

    • avoided or deferred reliability transmission facilities and aging infrastructure replacement; 
    • reduced loss-of-load probability or lower planning reserve margins; 
    • production cost savings; 
    • lower line losses; 
    • lower congestion from transmission outages; 
    • mitigation of extreme weather events and unexpected system conditions; and 
    • capacity cost benefits from reduced peak energy losses. 

Planners will have to give state entities six months to agree on a cost-allocation method, but they also have to propose a default method. They can decide to push through their default method and will not be required to file any alternative states come up with. 

That ability to override state desires — plus the end of the separate consideration of economic, reliability and public policy lines — led to Commissioner Mark Christie dissenting on the entire order, while Chair Willie Phillips and Commissioner Allison Clements filed a joint concurrence. 

“Not everybody is going to get everything that they want,” Phillips said during the meeting. “I don’t even get everything that I want, but that is the nature of these large proceedings and these large rules here at FERC. This rule cannot come fast enough. There is an urgent need to act to ensure the reliability and affordability of our grid. We are at a transformational moment for the electric grid with phenomenal load growth from a domestic manufacturing boom, unprecedented construction of data centers fueling an AI evolution, and ever-expanding electrification.” 

The resource mix is at an inflection point with aging infrastructure needing replacement, and a higher incidence of extreme weather has cost consumers billions of dollars over the past decade, he added. Transmission expansion has not kept pace with the changes, falling to an all-time low in 2022, and much of that was “Band-Aid” fixes, Phillips said. 

Christie said the Notice of Proposed Rulemaking was a bipartisan deal, but that bipartisanship did not carry forward into the final rule. (See FERC Issues 1st Proposal out of Transmission Proceeding.) 

In addition to ending public policy as a separate consideration, Christie also criticized the final rule’s requirement that planners consider demand from large corporate customers favoring specific generation types to serve their operations. 

“If we’re going to mix reliability projects with public policy projects, and these corporate-driven, preferred purchasing projects, then it’s only fair that state regulators have to have the ability to consent to the planning criteria, and especially the cost allocation in a big, big multistate RTO, like PJM,” Christie said in an interview. “That is absolutely essential. So that’s not in there now. There’s no requirement that states have to consent.” 

The NOPR did not spell out what would happen if states cannot come to an agreement, instead asking for comment on the issue. Clements told reporters that the decision to have a federal backstop made sense based on the record. 

“We need to have a federally jurisdictional backup if the states don’t come to agreement, and that is why we have a backstop ex ante approach,” Clements said. “States don’t have to use it; if they get together in a region and want to do something different — great.”  

The point where state regulators and an RTO might split on cost allocation is not going to occur until after the rule is implemented, she said. “But I wouldn’t suggest it’s a wise approach,” Clements said of regional planners overriding states. “I think transmission providers want this to work as well and are looking forward to working with the states.” 

Christie questioned why the majority even voted to let regional planners, including ISO/RTOs and groups of utilities outside them, override state cost-allocation preferences. 

“If you don’t think they’d ever do it, then why wouldn’t you agree to give the states the ability to consent?” Christie said. “Because the fact is, they can ignore it.” 

Phillips noted that he and Christie knew each other as members of the Mid-Atlantic Conference of Regulatory Utilities Commissioners before they came to FERC. He said he would never support a rule that tramples states’ rights in the planning process. 

“There’s a lot that Commissioner Christie said that I simply do not agree with,” Phillips said. “But I do agree with this: The most important job of our commission is reliability. I’ve been saying that since Day 1. So let me be clear now, because this rule is about reliability and affordability: I have complete confidence that it will be legally durable and that it will be upheld.” 

Another area where the three commissioners could not agree is whether the rule is reacting to the industry’s realities or actively seeking to drive the grid toward a preferred future. 

“It is not our job to do resource planning,” Clements told reporters. “States, private actors — they engage in choosing what kind of resources they want to have. It is the commission’s job to facilitate reliability and affordability of the transmission system in light of the choices that states and other actors are making outside of the agency.” 

Christie argued that the rule was being pushed out along with other policies the Biden administration favors. He noted in his dissent that he quotes several press reports linking the transmission rule to efforts to combat climate change. 

“What this is doing here is attempting to enact a major policy agenda that has never been passed by Congress,” Christie said. “And that alone makes it a major question. So, it’s a very important point in my dissent that this is not within the authority of FERC under the Federal Power Act.” 

The order will go into effect 60 days after its publication in the Federal Register. Transmission providers will be required to submit compliance plans for most of the order’s requirements within 10 months of the effective date. 

FERC Pulls Back on ROFR Rollback

One aspect of the NOPR that drew considerable debate was the proposed partial rollback of Order 1000’s elimination of most federal rights of first refusal, which opened regionally planned lines to competition. The commission had proposed establishing a conditional ROFR when a utility works with a partner on a project. 

The change was a major priority for utilities and their trade groups, including the Edison Electric Institute and WIRES Group, but it was opposed by competitive transmission developers, consumer groups and the Federal Trade Commission. 

The commission required transmission providers to identify opportunities to modify in-kind replacement of existing facilities to increase their transfer capability, known as “right-sizing.” Utilities will get to keep a federal ROFR over such right-sized projects that are in their territories. 

Order 1977 on Backstop Transmission Siting

FERC also issued Order 1977, which implements its new congressionally mandated authority to site transmission lines in a National Interest Electricity Transmission Corridor even when state regulators reject them (RM22-7). All three commissioners supported this order. 

The order “includes a Landowner Bill of Rights, codifies an Applicant Code of Conduct as one way for applicants to demonstrate good-faith efforts to engage with landowners in the permitting process, and directs applicants to develop engagement plans for outreach to environmental justice communities and tribes,” FERC said.

The one major change from the proposal was that FERC will not let transmission developers file for its siting approval at the same time as a state is reviewing a line. They will instead have to wait a year. 

Many states argued that allowing transmission developers to file at FERC while also pursuing a state certificate would effectively usurp their authority. (See FERC Backstop Siting Proposal Runs into Opposition from States.) 

The order will take effect 60 days after its publication in the Federal Register. 

Initial Takes

Senate Majority Leader Chuck Schumer (D-N.Y.) held a press conference call while FERC was still meeting to praise the final rule. 

“The clean energy incentives included in the Inflation Reduction Act have been a huge success,” Schumer said. “But much of that success would be lost without the ability to bring power from places that generate renewable energy to communities all across the country. A new historic advancement in our transmission policies has been desperately needed, and the rules released by FERC today will go a long way, a very long way to solving that problem. Simply put, these new rules will mean more low-cost, reliable, clean energy for the places that need it most.” 

Many proposed bills have been introduced this Congress to address transmission and other permitting issues, with Senate Energy and Natural Resources Committee Chair Joe Manchin (D-W.Va.) and Ranking Member John Barrasso (R-Wyo.) trying to get a deal through to simplify building infrastructure. Schumer said such efforts will be hard to get past a divided Congress this year. 

“I’ve told Joe Manchin it’s going to be virtually impossible to get something done,” he said. 

For his part, Barrasso blasted “FERC’s partisan vote,” arguing it would only add to electricity’s growing costs. 

“Today’s decision will force customers — often in rural states — to pay for new transmission lines even when those lines don’t provide any meaningful benefit to them,” Barrasso said. “It is the Holy Grail for liberal politicians in California and New York and corporate executives who want others to foot the bill for their climate obsession. I have no doubt the cost of energy will be at the top of every voter’s mind later this year.” 

House Democrats welcomed the final rule, with Reps. Sean Casten (D-Ill.) and Mike Levin (D-Calif.), co-chairs of the Sustainable Energy and Environment Coalition’s Clean Energy Deployment Task Force, calling it a vital step toward a fully clean economy. Despite Schumer’s doubts, they said they would like to pass additional legislation on transmission — especially their own Clean Electricity Transmission Acceleration Act. 

“This rule takes steps towards ensuring our grid is meaningfully planned and the costs of the necessary transmission buildout are fairly distributed by those who will benefit from the new capacity,” they said in a joint statement. “Americans today are already bearing the costs of an improperly planned grid; transmission planners have thus far not adequately accounted for the new forms of cheap, clean energy that are being deployed on the grid at an accelerating pace. A reliable, affordable and clean grid is only achievable with proper, comprehensive and forward-looking grid planning.” 

Americans for a Clean Energy Grid praised the rule, saying it ensures the grid will be planned in a proactive and comprehensive way. 

“Now, it’s time to implement this rule,” ACEG Executive Director Christina Hayes said. “Regions must develop their compliance filings over the next few months so that transmission can be planned and developed as soon as practicable. We look forward to working with and supporting the interested parties as they move forward with the next steps in compliance and build out the 21st-century grid.” 

Advanced Energy United welcomed the rule, saying it would help lower consumer bills by making a more efficient grid and opening access to cheap power. 

“Families and businesses are paying the price for utilities’ and grid operators’ failure to address our critical electricity infrastructure needs,” CEO Heather O’Neill said in a statement. “Building more multistate transmission lines unclogs the traffic jams on America’s electricity superhighways and unlocks our ability to keep up with our growing energy needs. This FERC order sends the message that transmission planning needs to change and recognizes that states deserve a central role in ensuring a reliable electric grid built for the future.” 

EEI was not as enamored as the clean energy trade groups, citing disappointment with the decision not to roll back Order 1000’s ROFR provisions, among other issues. 

“Additionally, the failure to provide regional flexibilities for evaluating project benefits in the final rule will lead to longer compliance processes and, ultimately, could slow the development of much needed transmission projects,” EEI Vice President of Regulatory Affairs Phil Moeller said in a statement. “A one-size-fits-all approach does not work, as different regions have different needs and different states have different policies.” 

Environmental groups generally praised the final rule, with Sierra Club Executive Director Ben Jealous saying it “follows the letter of the law” and will save ratepayers money. 

“As President Biden’s Inflation Reduction Act continues to usher in the clean energy future through deployment of solar, wind and battery storage, this transmission standard will allow utilities to deliver Americans clean, affordable electricity, even in the face of rising demand and extreme weather caused by climate change,” Jealous said in a statement. “With the standard now in place, FERC must be vigilant to ensure strong implementation in order to maximize the benefits for reliability and consumers.” 

K Kaufmann contributed to this report. 

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How Sea Level Rise, Coastal Flooding Threaten Boston’s Grid

For much of its early history, Boston was a city expanding into the sea.  

A hilly peninsula prior to colonization, the city began the labor-intensive process of removing its hilltops to fill in the surrounding coves, marshes and mud flats at the end of the 18th century.  

The summit of Beacon Hill, adjacent to the Massachusetts State House, was carted off in the early 1800s, while Mount Vernon and Pemberton Hill, which formed the peninsula’s “Trimountain” landmark alongside Beacon Hill, fared even worse. In the words of Boston historian Walter Muir Whitehill, “the hills have all but disappeared.”

Today, more than half the city is built on a landfill foundation of former hilltops and assorted city waste. As a result, a major portion of Boston’s streets, bars, apartments and power infrastructure are located just above historical flood lines.

Boston topography 1630 to present | The Boston Public Library

The outward expansion has enabled Boston to become the city it is today but also has made it especially vulnerable to the rising tides that threaten to force the city into retreat.  

By 2100, the sea level around Boston is projected to rise by two to five feet, according to a 2022 report by the University of Massachusetts Boston.

The report projected precipitation intensity to increase by 20 to 30%, while sea level rise likely will push up groundwater levels and increase groundwater salinity along the coast. If emissions continue at current rates, 100-year flooding events could become annual occurrences by the end of the century. 

“Risk-averse end users of these projections should consider the possibility of sea level outcomes above the likely range, especially under higher GHG emissions,” the UMass report noted. “For long-term planning and long-lived coastal assets, we stress that sea level will continue rising beyond 2100 under all GHG emissions scenarios.” 

Rising Costs of Resiliency, Recovery

In Boston and throughout the broader region, climate-fueled extreme weather events already are stressing essential energy infrastructure. 

“We see a lot of concern about the ability of the grid to withstand even current — not to mention future — storms, sea level rise and other climate impacts,” said John Walkey, director of climate justice and waterfront initiatives at the environmental justice nonprofit GreenRoots.  

As climate change accelerates, “all our past planning and forecasts go out the window,” Walkey said.  

Massachusetts’ electric utilities have incurred major costs associated with storm recovery in recent years. Eversource, one of the state’s two major electric distribution companies, is seeking to recover about $339 million in costs associated with three storms that occurred between 2021 and 2022, including $176 million from a single 2021 Nor’easter (D.P.U. 22-143). 

Over the past decade, Eversource’s contributions to its storm fund, which is intended to stabilize the impacts of storm costs on ratepayers, have increased from about $5 million to $31 million annually (D.P.U. 22-22).  

In the fall of 2021, Eversource reported its storm fund had a $122 million deficit, which the company attributed in part to increasingly frequent storms “due to weather patterns and meteorological characteristics associated with climate change.” 

In a recent interview, Massachusetts Department of Public Utilities Chair Jamie Van Nostrand emphasized it’s the utilities’ responsibility to prepare their systems for increasing pressures from climate change. 

With more frequent and severe extreme weather events and increasing property values, elevated storm costs are “not necessarily a matter of the utilities being imprudent,” Van Nostrand told RTO Insider. “But we’ll also be looking closely at, ‘Could that have been avoided? Could you have designed your system in a way that would have been more resilient?’” 

In 2022, Massachusetts passed a bill requiring the state’s electric utilities to file electric-sector modernization plans (ESMPs) with the DPU every five years. The bill requires the utilities to detail how they plan to upgrade their systems to facilitate the clean energy transition and mitigate climate damage. (See Mass. Utilities Submit Grid Modernization Drafts.) 

The utilities filed their final plans in January, which the DPU should rule on in late August, Van Nostrand said. 

“Even without that specific statutory directive, I think that part of our job is to put the utilities on notice that we’re watching, and we want you to take [climate resilience] into account,” Van Nostrand said, adding that utilities will “run the risk of a prudence disallowance” if they incur costs that could have reasonably been avoided by proactive climate mitigation.” 

The utilities’ ESMPs outline major investments to meet increasing peak loads and enable the transition to more distributed generation. Eversource estimates it will need to build 17 new substations and upgrade 26 substations by 2035.  

“It’s very timely that we’re looking at the climate change resilience piece,” Van Nostrand said, “because we’re going to be installing a lot of substations, upgrading a lot of substations, and we want to make sure the utilities are mindful as they’re making all these investments.” 

While storm costs are often driven by downed trees and branches, large flooding events can pose a significant threat to substations. 

National Grid, Massachusetts’ other major electric utility, noted in its ESMP filing that flooding in its Rhode Island service territory in 2010 forced the company to remove eight substations from service and caused “significant customer outages and loss of high-value substation equipment.” 

The company wrote that it used Federal Emergency Management Agency (FEMA) flood maps to analyze its substation fleet in the aftermath of the events to identify vulnerabilities. 

“Flood mitigation efforts have been implemented at approximately 40 substation locations with approximately 20 additional projects planned,” National Grid wrote. 

Elli Ntakou, Eversource’s manager of system reliability and resiliency planning, said the utility assesses risk based on FEMA flood data and sea level rise projections from the City of Boston and the National Oceanic and Atmospheric Administration. 

“Especially for sea level rise, we want to be comprehensive,” Ntakou said.  

Elevation in East Boston

Sea level rise resiliency has been one point of contention in the lengthy fight over Eversource’s proposed substation on the banks of Chelsea Creek in East Boston, which has led to demonstrations and arrests of protesters attempting to stop construction.  

Environmental justice organizations and residents have argued Eversource failed to conduct adequate community engagement on the project and have expressed concern that future climate-driven flooding could inundate the substation, endangering the surrounding neighborhood.

GreenRoots and the Conservation Law foundation have a pending legal challenge before the Massachusetts Supreme Judicial Court regarding the Energy Facilities Siting Board’s (EFSB’s) approval of the project (EFSB 14-04A).  

“We don’t feel as if they really prepared for the lifespan of this facility, [or] they prepared for the lifespan of a transformer,” said Walkey of GreenRoots, adding that substations can last for more than a century.   

Eversource considered sea level rise over a 40-year equipment lifespan and selected a design flood elevation — “the lowest elevation at which the Substation equipment should sit on the site” — of four feet above the 500-year flood line.  

Eversource said the substation “was approved following a comprehensive, yearslong public review process” and that the company “comprehensively demonstrated that the project is designed to mitigate flood risks well beyond any flood study for the project.” 

The EFSB ruled Eversource “appropriately addressed risks associated with sea level rise” and added that “building the substation at a higher elevation would likely add costs to project development and provide unclear benefits.”  

Future Uncertainty

One major challenge of planning for coastal flooding is the high level of uncertainty associated with projecting future emissions, as well as how largescale earth systems will react to different warming scenarios. 

While Boston is likely to experience sea level rise of two to five feet, “that’s really all we can say, because it depends on the emissions of greenhouse gases,” said Paul Kirshen, professor of climate adaptation at UMass Boston and a lead author of the UMass climate impacts report.  

“If we can get to net zero by 2050, it could only be two feet. If we keep on the rate we’re going, it could be five feet,” Kirshen said.  

Projection of a hundred-year flood with three feet of sea level rise | City of Boston

He added there is an “outside chance” that sea level rise could reach up to 10 feet by the end of the decade, depending on the degree of melting on ice sheets in Greenland and Antarctica. 

“It’s a low probability,” Kirshen said, “but that would obviously be a real game changer.” 

Climate change also could increase the potential for low-probability, high-consequence compound flooding events in which river flooding coincides with a storm surge, Kirshen said.  

“We’re at the confluence of three rivers — the Mystic, the Charles and the Neponset River — and there’s always the possibility of those rivers being flooded from precipitation at the time that we get a major coastal storm,” Kirshen said. “Not only would you get flooding from the ocean from the storm surge, but you’d also get the Charles River and the Mystic River overflowing their banks.” 

To help account for the changing climate risk profiles, in recent years the DPU has mandated that newly sited projects reassess their climate vulnerability every five years and take any additional necessary mitigation measures. 

“It just makes sense if you’re installing energy infrastructure that’s going to have a lifespan of 30, 40, 50 years,” said DPU Chair Van Nostrand. “We’re always getting more information, and if anything, I think the information we’ve gotten is a little bit scarier. … Sea level rise might be even worse than we were thinking.” 

Some environmental organizations and legislators are looking to require even more comprehensive climate resilience planning from the utilities. One bill reported favorably out of the legislature’s Telecommunications, Utilities and Energy Committee would require the state’s investor-owned utilities to submit a climate vulnerability assessment and adaptation plan every five years. 

Johanna Epke, staff attorney at the Conservation Law Foundation, said current requirements have provided limited visibility into how the utilities are planning for climate impacts.  

“They’re not required to file any of their modeling or any of their assessments,” Epke said. “We want that out in the public space, we want to be able to scrutinize that, and we want to have experts in the advocacy community comment on that.” 

Van Nostrand said he thinks the DPU already has the statutory authority to require climate vulnerability assessments as part of the ESMP process.  

“As a result of the 2022 climate law, we will be making specific findings on climate vulnerability assessments when we issue the August order on this first round of ESMPs,” Van Nostrand said. “Apart from that, we can also rely on our broad regulatory oversight powers to be able to say, ‘We think that it’s part of utility practice that you perform this kind of a study and manage your system in a way that manages risks.’”  

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ASE: Energy Transition Must Put Demand-side Efficiency, Flexibility First

WASHINGTON ― Gene Rodrigues, who heads the U.S. Department of Energy’s Office of Electricity, managed to get through a thundering, seven-minute keynote at the Alliance to Save Energy’s Policy Summit on May 8 without even one de-rigueur mention of the Inflation Reduction Act, Infrastructure Investment and Jobs Act or President Joe Biden’s economic agenda.  

Rather, he came to the summit to deliver a ringing endorsement of ASE’s new campaign to convince the energy industry, state regulators and Capitol Hill lawmakers that “demand is the new supply.”   

In the past, the energy industry “looked at everything from one end of the microscope,” said Rodrigues, who spent a large chunk of his 23 years at Southern California Edison working on demand-side initiatives. “If you need more reliability, if something goes down and you just need more power, if you need to ensure that everyone has access to the benefits of energy, then you … just build more. We need more, bigger plants. We need more transmission corridors. We need, we need, we need. That is the most inefficient way to think about solving the problem.” 

Creating a net-zero economy ― with electrified buildings, transportation and industry ― will mean major increases in energy demand, so using a full array of demand management strategies and technologies will be not only critical, but “obvious,” he said. “It is a basic concept of efficiency, of ensuring that the steps we take are economic, impactful and they reach every single American no matter where he or she resides … It is an expression of common sense.” 

ASE CEO Paula Glover similarly framed the combination of aggressive efficiency and demand management as “the backbone of any energy transition that we aspire to have that is going to be equitable, reliable, resilient and affordable.” 

Demand is the new supply means “transforming energy demand into … dynamic, responsive supply. [It] is necessary and has to start now,” Glover said in her opening remarks at the summit. “This approach is crucial for stabilizing our grids and distributing energy more equitably across communities.” 

Conference panels and speakers presented different approaches to growing demand management as supply, from the consumer and regulatory paradigm shifts needed to scale virtual power plants to new research from Lawrence Berkeley National Laboratory (LBNL) showing the impact of efficiency on regional load curves.  

Electrification without aggressive efficiency could result in summer peak demand not only increasing, but shifting to later in the evening, said Andrew Satchwell, deputy leader in LBNL’s Energy Markets and Policy Department. Produced in partnership with The Brattle Group, the study also found roughly half the regions studied could see a shift from summer to winter peaking due to the inefficiency of “a lot of electric resistance building heating,” Satchwell said. 

But the study also showed that a combination of aggressive demand- and supply-side measures could slash greenhouse gas emissions in the building sector to 91% below 2005 levels by 2050 without any major increase in building electricity use. Further, leveraging building efficiency and flexibility could provide $100 billion in power system savings per year by 2050, which could offset more than a third of the costs of grid decarbonization.  

“We see a strong potential for energy efficiency to reduce emissions in the near term, while the grid is still decarbonizing, that then enables later reductions from … electrification under a harmonized grid,” said Aven Satre Meloy, a computational research scientist and engineer at the Berkeley Lab.  

Calling the study a “clear-eyed view of the economic case” for demand-side measures, Rodrigues ended his keynote with a call for industry stakeholders to “work on both ends of the scale to balance the grid. Demand is the new supply does not push anything off the table,” he said. “For those who believe in all-of-the-above, it’s just a way to work smart; work smarter, not harder.” 

The LBNL-Brattle study found that by combining electrification with aggressive efficiency, the U.S. could reduce CO2 emissions from the building sector 91% below 2005 levels by 2050. | Lawrence Berkeley National Laboratory

Start Right Now

While utility executives frequently say that the least expensive kilowatt-hour is the one you don’t use, demand-side initiatives in general have not had a strong profile in the energy transition.  

In its 2023 Utility Scorecard, the American Council for an Energy Efficient Economy found that the nation’s 53 largest utilities had decreased their spending on efficiency by 4.9% in the five years since ACEEE’s last utility rankings. That cut in spending resulted in a 5.4% decrease in energy savings and a 19% drop in peak demand reductions. On average, the ranked utilities spent 2.2% of their revenue on energy efficiency. 

According to a January 2024 tally from the International Code Council, 13 states have adopted the latest, 2021 International Energy Conservation Code for residential buildings, while only 11 have adopted IECC 2021 for commercial buildings. Two more, Maine and Massachusetts, have adopted the 2021 updates as “stretch” codes.  

IECC codes are updated every three years. Six states still are using the 2009 code.  

The LBNL-Brattle study finds an aggressive approach to efficiency and demand flexibility will be vital for the U.S. to have any chance of hitting Biden’s goal of cutting economywide GHG emissions to net zero by 2050 without major increases in demand and grid impacts. 

The scale of such efforts could be daunting. The building sector accounts for 35% of U.S. carbon dioxide emissions and 74% of electricity sales, according to LBNL. The study looks at a range of scenarios tracking the effects of cutting emissions and electricity consumption through various combinations of electrification and low, moderate and aggressive energy efficiency and demand management.  

LBNL’s most aggressive scenario would require 98 million to 141 million fossil fuel or electric-resistance water heaters to be replaced with heat pump water heaters by 2050, as well as high-efficiency retrofits for building envelopes on 109 million existing homes and up to 43 billion square feet of commercial space. Advanced HVAC controls also would be needed for more than 75% of homes and 50% of commercial buildings. 

And, Satre Meloy said, “It needs to start happening right now in order to achieve that very dramatic or very favorable building-centric future in 2050.” 

Electrification with no or low efficiency would cut CO2 emissions but almost certainly would result in increased electricity demand, the study finds. The effects of moderate and aggressive efficiency are more variable; emissions would go down, but electricity use could rise or fall, depending on a range of factors.  

One example, the study’s aggressive efficiency scenario factors in “breakthrough” technologies ― such as super-efficient building envelopes and energy management systems ― are in the research and development phase but expected to reach commercial scale and price points by 2030 or 2035. 

Increasingly rigorous building efficiency codes and standards also will be needed, Satre Meloy said. “Failing to do these things is substantially reducing the total avoided emissions” by 40% to 58%, he said.  

The effects on the grid also could be substantial, with “inefficient electrification” leading to increased peak and shifting demand patterns, Satchwell said. In Texas for example, the study found that efficient electrification could drive the state’s summer peak below a business-as-usual level. For a winter-peaking system in the Northwest, efficiency could cut in half any increase due to electrification.  

Efficiency and flexibility mitigate electrification load increases in both summer- and winter-peaking systems. | Lawrence Berkeley National Laboratory

Shifting the Paradigm

So, what it will take to get building efficiency and demand flexibility technologies ― like virtual power plants ― to commercial scale and well-integrated into distribution systems? The discussion during a panel on scaling VPPs centered more on paradigm and regulatory shifts than the technologies themselves. 

For Jessica Granderson, director of LBNL’s Building Technology and Urban Systems Division, buildings are an “underexploited resource” and the “central hub in the transfer of clean electrons in our energy transition to and from that clean grid.” 

“Our buildings have built-in storage already, right in the mass of the building, in the fabric of infrastructure, in the chilled and hot water that we’re using to serve those loads,” Granderson said. “We have the technologies, the communications and the standards now [that] we didn’t previously have to access that built-in storage and exercise it dynamically.” 

Mary Sprayregen, global head of regulatory affairs and global market development at Opower, sees a major misalignment between projections of growing residential energy efficiency and demand management and the current reality that about 8% of households are enrolled in utility demand-response programs.  

“And that number has not changed over the last several years despite all the attention we are drawing to it,” Sprayregen said. “How do we engage these untapped resources in everyday houses in a way that everybody can participate, but … that is not necessarily controllable, and it’s not necessarily device-based, but it’s behavior-based?” 

Opower designs and runs such programs for utilities. 

Marisa Uchin, chief strategy and growth officer at Franklin Energy, called for a reimagining of the power system “because we have distributed resources on the supply side hidden on the demand side. We have the opportunity to create the VPPs or to create sources of power that are … on a different size and scale” and can be “distributed any place where potentially demand and supply chains are complex.” 

But technology changes at the residential level generally are driven by comfort, upfront cost and a crisis ― the breakdown of a major appliance ― Sprayregen said.

Granderson agreed but called for “changing that paradigm to something that is like where our decisions are system-optimal, and I think, we have to be really cognizant and intentional that that is the change we’re looking to drive. … So, we’re going to think about the ways we combine those solutions to reach everyone in different markets and contexts.” 

Another major hurdle for Sprayregen is designing appropriate incentives for utilities to accelerate deployment of efficiency and demand flexibility. Regulatory decision-making is rooted in an inherent conflict between “capital expenditures versus operational expenditures,” she said. “So, how do we get past that?” 

Sprayregen, Granderson and Uchin agreed artificial intelligence will be the next critical tool for optimizing the system impacts of energy efficiency and demand management.  

“When it comes to policymakers, specifically utility regulators, there has got to be a pathway where software solutions are on par with capital expenditures,” Sprayregen said. “We’ve got to level that playing field.” 

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Consumer Advocates, Environmentalists Urge Holistic Thinking at PJM

BALTIMORE — The Public Interest and Environmental Organization User Group (PIEOUG) discussed costly generation deactivations, RTO versus member filing rights over regional planning and long-term transmission projects with members of the PJM Board of Managers on May 8, the final day of the 2024 PJM Annual Meeting. 

Much of the discussion centered around transmission, how PJM can increase the amount of regional planning it conducts, the cost of utility-designed supplemental projects and a proposal to shift filing rights over the Regional Transmission Expansion Plan (RTEP) from the Members Committee to PJM’s board. (See Members Vote Against Granting PJM Filing Rights over Planning.) 

Ari Peskoe, director of the Electricity Law Initiative at Harvard University, argued that proposed revisions to the Consolidated Transmission Owners Agreement (CTOA) to grant PJM sole filing rights over the RTEP under Federal Power Action Section 205 include language that would allow TOs to supplant PJM-initiated projects with more expensive plans introduced by utilities and would create a “shadow governance” where CTOA signatories could challenge PJM prospective Section 205 filings, PJM regional plans, or other PJM actions through a confidential mediation process. 

Peskoe argued the CTOA revisions to allow utilities to declare their intention to build a similar project as one in the RTEP could interact with existing tariff language prohibiting PJM from “planning a duplicative project” to force PJM to remove components from its plan without consideration of the merits of each proposal or whether they are likely to be built. Following the PIEOUG meeting, he submitted a letter to the board recounting his comments. 

“The CTOA creates new veto powers and broad rights of first refusal, as well as new opportunities for each utility to interfere with regional planning, PJM’s FERC filings and other PJM actions. The new CTOA also subjugates PJM’s RTO status to the CTOA, reduces transparency for PJM members and states, and limits PJM’s options as it navigates the energy transition. It would create a new shadow governance system where utilities will have the advantages,” he said in the letter. 

The MC overwhelmingly rejected corresponding revisions to the PJM Operating Agreement and tariff to transfer filing rights May 6, which several members argued were being rushed through the stakeholder process and could lead to PJM being able to make unilateral economic determinations about the viability of generators. The transfer would require revisions to both the CTOA through the agreement of the Transmission Owners Agreement-Administrative Committee (TOA-AC) and the PJM board, as well as the amendment of the OA and tariff. The board notified stakeholders May 10 it’s deferring deciding on the CTOA revisions until after the FERC filing on long-term transmission planning, noting the MC’s rejection of the changes. 

Attorneys representing transmission owners supporting the CTOA revisions responded to Peskoe’s comments in a May 9 letter to the board, stating the changes would not empower TOs to remove PJM-selected projects from the RTEP in lieu of their own, but rather would allow them to continue to move forward with projects at the risk of FERC finding them imprudent. 

“Nothing prevents PJM from continuing with the RTEP project,” the letter states. “PJM is obligated to go ahead with the regional project. If any change occurs, it would be PJM revising its project to address the Transmission Owner project need, in which case the risk would be on the Transmission Owner to move forward with its project, as outlined above.” 

The TO letter also states the new mediation process is similar to those approved by the FERC in the past and would allow PJM or TOs to be party to a complaint to dispute the results at the commission. 

Consumer Advocates Call for More Holistic Thinking at PJM

Brian Lipman, of the New Jersey Division of Rate Counsel, said the number of stakeholder meetings and the pace at which consequential topics are discussed can make it difficult for consumer advocates to stay engaged. His concern about timing extends to the Base Residual Auction (BRA) schedule as well, which has been compressed from its usual three-year advance cycle to allow multiple market changes to be implemented. He said running auctions in close succession increases the odds of errors being introduced, as he said happened with the results of the 2024/25 BRA for the DPL South zone, where FERC ordered PJM to recalculate the results using parameters that caused a substantial increase in prices. (See related story, Following Court Ruling, FERC Reluctantly Reverses PJM Post-BRA Change.)

“It’s so important that we make sure that PJM is not making mistakes … the timing, the rushing makes us nervous,” he said. 

Lipman said the advocates’ outside position in the market and planning processes make it difficult for them to receive and analyze data about the drivers behind costs faced by consumers. Generation and transmission owners hold data about their assets and operations that can be difficult for advocates to request, even when it is shared with PJM. 

Board Member Vickie VanZandt said determining the most reasonable cost requires breaking down silos and holistic solutions, but that transmission owners are best placed to understand the condition of their infrastructure. She questioned how the advocates view where supplemental projects fit into risk management. 

Lipman responded that TOs look only at their own assets, whereas PJM can consider regional solutions that could meet the needs of multiple supplemental projects at a lower cost. However, it does not factor local transmission issues into its RTEP proposals. 

“We’re losing those opportunities, and frankly, they’re costing ratepayers a significant amount of money,” he said. 

Environmentalists Call for More Flexibility Around Deactivations

Casey Roberts, of the Sierra Club, said PJM’s lack of a proactive plan for replacing retiring resources is missing opportunities to improve the reliability and flexibility of the grid, speed the development of clean energy and save consumers money. She said deactivating generators tend to be older and have lower capacity factors that contribute to them receiving capacity market signals that they no longer are needed for resource adequacy. By holding onto those resources through RMR contracts to resolve transmission violations, she argued the reliability of the grid is dependent on resources that themselves are less reliable. (See PJM Rejects Storage as Alternative to Brandon Shores RMR.) 

Generators operating on RMR contracts also prevent the redeployment of transmission capability, slowing the pace of new generation coming online, including those that might resolve the same violations necessitating the RMR contract. 

She said a study conducted by Gridlab and Telos Energy looking at the feasibility of installing an 800-MW battery at the point of interconnection of the 1,295-MW Brandon Shores found that storage paired with transmission upgrades could resolve the violations at a lower cost than PJM’s solution. And it would replace a 40-year-old coal generator with a battery boasting a quick ramp rate and other parameters that thermal generators may lack. 

Introducing alternatives to operating generators on RMR contracts while lengthy transmission projects are completed would require a mechanism for CIRs to be transferred to new resources, a longer notification period for generation owners seeking to take units out of commission and TOs working grid-enhancing technologies (GETs), such as dynamic line ratings (DLRs), into their solutions.  

Katie Siegner, of RMI, said FERC has made clear that its Order 2023 on generator interconnection should be seen as a floor by RTOs and encouraged PJM to not simply comply with its requirements. She said incorporating GETs into the network upgrade studies performed by PJM and developers for new resources could speed the entry of renewable resources and save customers $1 billion annually by reducing transmission congestion and integrating lower-cost resources onto the system. (See RMI Report: GETs Could Speed Renewable Development, Save Consumers Billions.) 

Nick Lawton, of Earthjustice, said development of clean energy, deactivation of fossil generation and transmission planning are intricately linked, but are viewed through siloed stakeholder processes. He said about 5% of the energy produced in PJM is generated with renewable resources, while other regions are far ahead. 

“It’s hard for me not to conclude that PJM is behind,” he said, adding that means the RTO doesn’t need to reinvent the wheel because the success of others shows the path forward. 

Lawton also argued the backlog of proposed generation projects in the interconnection queue has contributed to the slow pace of new entry in PJM and urged staff to continue improving the cluster-based approach the RTO initiated this year. (See PJM Initiates Transitional Interconnection Queue.) 

“PJM can make the energy transition work but the pace of the transition depends on how quickly PJM acts,” he said. 

Board of Managers Chair Mark Takahashi said about 40 GW of generators have cleared the interconnection queue and have signed interconnection service agreements (ISAs). Most are renewables, but they haven’t yet moved to construction. 

Lawton responded that in many cases, the amount of time it took resources to receive an ISA affected their ability to hit the ground running once it arrived, particularly because of changing economic conditions. 

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PJM Members Committee Briefs: May 6, 2024

Stakeholders Re-elect 3 PJM Board Members Over Consumer Dissent

BALTIMORE — The Members Committee voted to re-elect three members of the PJM Board of Managers, placing Paula Conboy, David Mills and Vickie VanZandt on the board for additional three-year terms. 

Board member and Nominating Committee Chair Dean Oskvig said all three candidates are completing their first term on the board and “hit the ground running” in his experience working with them. Conboy and Mills were first elected to the board in 2021, while VanZandt was appointed to the board in September 2022, following the resignation of board member Sarah Rogers. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), told the MC that several advocates were voting against their re-elections to express frustration and waning confidence with the board’s handling of the clean energy transition, market power concerns and the lack of analysis on the cost impacts of transmission. 

PJM Board Member Dean Oskvig | © RTO Insider LLC

Poulos also stated there’s uncertainty around the functioning of the capacity market and a feeling that the board rushed stakeholders to a vote on proposed revisions to the Operating Agreement and tariff to transfer filing rights over regional planning from PJM’s membership to the board. 

The MC voted against that proposal May 6 and on May 13 the board issued a notification that it’s deferring action until after the May 13 FERC order on regional planning. (See Members Vote Against Granting PJM Filing Rights over Planning.) 

Because the board tends to speak as a single body, Poulos said it’s difficult to discern where individual board members stand on issues and the advocates’ “no” votes were not against any of the candidates as individuals, but rather to signify dissatisfaction with the direction the board has taken. 

Productive Year of Changes in 2023, Say Asthana and Midgley, Challenges Ahead

PJM CEO Manu Asthana opened the RTO’s 2024 Annual Meeting stating the organization has had an exceptionally strong year of reliability and is in the process of implementing market redesigns drafted throughout 2023 to poise PJM to continue performing well. 

Changes to the Reliability Pricing Model (RPM) created through last year’s Critical Issue Fast Path (CIFP) process calibrate market signals to the energy transition’s new realities, he said. The changes also move ahead on improving generation accreditation, adding sophistication to risk modeling and enhancing testing of generator’s capabilities, he added. (See FERC Approves 1st PJM Proposal out of CIFP.) 

Asthana said the January 2024 Winter Storm Gerri presented many of the same challenging conditions as the December 2022 Winter Storm Elliott, which pushed PJM into some of its most severe emergency procedures and was one of the contributing factors to launching the CIFP process. This time around, however, transmission and generation performance improved, and PJM’s load forecasting was accurate in the days ahead of the storm. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.) 

“We learned from the experiences of Elliott, and we saw it come to fruition in Gerri,” he said. 

PJM also initiated the transition to a cluster-based approach to studying new generation interconnection requests in 2023, Asthana said, setting a goal of completing the fast-track queue this year. 

“We’re making a lot of process on generation interconnection, which I feel good about,” he said. 

The acceleration of the clean energy transition is catching the world flat-footed, and more work is needed at PJM, he said. Generation deactivations, new entries and the pace of load growth are surprising, particularly with the introduction of data centers, electric vehicle charging and hydrogen production load, Asthana said. The timing of the transition largely is out of PJM’s control and policy tradeoffs likely will be needed but he said discipline and effort in the stakeholder process can reveal solutions. 

“There is a lot of work that we still have to get right working together and time is not our friend,” he said. 

MC Chair Sharon Midgley, Exelon vice president of federal regulatory affairs, said the CIFP changes and a proposed regional planning paradigm will improve PJM’s ability to meet rapid load growth and changes in the generation mix. PJM’s proposed long-term regional transmission planning (LTRTP) process is being considered by the Markets and Reliability Committee, which deferred a vote April 25 to await the FERC regional planning order. (See “Stakeholders Defer Vote on Long-term Planning Proposal,” PJM MRC Briefs: April 25, 2024.) 

“I am cautiously optimistic that we will see some order of LTRTP implemented at PJM in the short term,” Midgley said. 

She also highlighted the proposal to transfer Federal Power Act Section 205 filing rights over the transmission planning protocol to PJM, stating PJM will need every tool at its disposal during the clean energy transition. PJM currently is the only RTO that does not have these rights over its planning rules.  

Stakeholder collaboration also will need to be centered in PJM’s efforts to navigate the transition, she said. “It is incumbent on everyone in the room to work together to ensure reliability through the energy transition.” 

PJM Panel Discusses Innovation and Technology

PJM held a panel on its efforts to use innovation to find solutions to the challenges posed by climate change, generation interconnection and control-room operations. The panel was moderated by Chief Communications Officer Susan Buehler and featured Chantal Hendrzak, executive director of IT operations and architecture; Dave Souder, executive director of system operations; and Emanuel Bernabeu, senior director of applied innovation and analytics. 

As more intermittent resources come onto the grid and weather becomes less predictable, Souder said forecasting needs to look not only at the storms’ magnitudes but also their precise timing to understand how weather may impact available generation, adding that even thermal resources can be affected by higher water and ambient air temperatures. He said PJM is looking at expanding its data science team to investigate factors such as the impact ice can have on wind turbines, wildfires interrupting solar output and high winds disrupting thermal generators. 

Machine learning can be employed in the control room to analyze past outages and the responses taken to determine which solutions may be best employed in real-time operations. During the June 2022 derecho that caused outages in Ohio, Bernabeu said technology could have reduced load shedding by about 20% and allowed grid operators to make critical decisions more quickly. 

Hendrzak said AI tends to be limited by its focus on learning from past experiences, but in the context of cybersecurity it can be used to develop a baseline pattern of normal user behavior to detect anomalous activity that could signify an intrusion. 

Bernabeu said one of the challenges in using machine learning to improve operations is the infrequency of major events on the grid, increasing the importance of interregional information sharing about outages. 

“It’s a terrible thing to waste a blackout so I always go and inspect everything about them,” he said. 

Hendrzak said she foresees a role for AI in the generation interconnection process to aid developers in identifying the best locations to site resources with minimal grid impacts, as well as for PJM to run network upgrade studies in parallel and to identify which projects are the most likely to succeed in reaching commercial operation. Souder said this will become increasingly important as the resource mix changes and it becomes more difficult for transmission owners to take lines down for outages. 

One of the challenges PJM and the electric industry face when integrating new technologies is the availability of data scientists. Out of the hundreds of programs PJM has designed in-house or through contractors, Hendrzak said they tend to be written by the same groups of industry-specialized engineers. 

Stakeholders Endorse GDECS Revisions

The committee endorsed a slate of revisions to PJM’s governing documents recommended by the Governing Document Enhancement and Clarification Subcommittee (GDECS), the most notable of which was changing several references to “end-use customers” to be lowercased. Changes also included removing outdated terminology, grammatical corrections and updating cross references. 

PJM Counsel Daniel Vinnik argued the uppercasing of end-use customer in multiple sections related to energy efficiency and demand response was an error and was not meant to limit participation in those programs to PJM members in the End-use Customer sector. He said PJM’s implementation of the language has remained the same before and after the uppercasing and noted the formatting was inconsistent throughout the sections. 

Paul Sotkiewicz, of E-cubed Policy Associates, said he’s concerned about making substantive changes through the GDECS process rather than bringing the revisions through the stakeholder process with an issue charge. He argued that some of the uppercasing may not have been an error, particularly in Schedule 6 language around energy efficiency. 

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Study: PJM Queue Wait Times Contributing to Longer Construction Periods

Lengthy wait times in PJM’s generator interconnection queue are interacting with siting and permitting timelines, supply chain disruptions and inflation to contribute to increasingly long construction periods, according to a study released last week by Columbia University’s Center on Global Energy Policy. 

The report, “Outlook for Pending Generation in the PJM Interconnection Queue,” surveyed 30 developers with projects in the “advanced stage” of the queue regarding the amount of time it would take for them to reach commercial operations after receiving an interconnection service agreement (ISA) and what major roadblocks could stymie those projects. 

“The key finding from the survey is that PJM’s increasingly lengthy interconnection process is exacerbating siting and permitting challenges and leading to knock-on delays in equipment procurement and financing decisions, suggesting the timeline for new generation in this market will likely remain long for the foreseeable future,” wrote the authors, Abraham Silverman and Zachary A. Wendling. “Given the importance of new entry to keeping prices competitive and maintaining reliability amid the retirement of older fossil resources, PJM will need to find ways to reduce interconnection delays or reconsider when those fossil resources should be retired.” 

The amount of time for a project to go from design to completion has been increasing over the past five years, the study said, and in PJM, the time it takes for a new interconnection service request to receive an ISA has increased from two years to five. 

If they were to receive an ISA today, participating developers said about 1% of the 249 projects they collectively have in PJM’s queue would be able to reach commercial operation within a year, while 26% could be completed within two years and 45% would take even longer. Among the 28% of projects with an in-service date conditioned on factors that made completion difficult to predict, siting and permitting was the largest source of uncertainty, along with supply chain constraints and the cost of transmission upgrades. 

Because local siting approvals and permits tend to be valid for up to two years, developers said uncertainty around their timelines for receiving an ISA has led many to wait until their interconnection studies have been complete to seek new permits, which can add time to how long it takes projects to get off the ground after PJM has completed its studies. 

One developer interviewed as part of the study described the interaction between the queue and permitting as “a bit of a chicken-and-an-egg problem: Ideally you would time these things so [permitting and construction] would come together, but until you have some kind of certainty that you are going to get an interconnection, we’ve been unwilling to make massive spending on permitting.” 

State regulations and siting requirements can complicate the matter as well, with West Virginia and New Jersey called out by developers for having rules that prove difficult for solar developers to navigate, and local authorities opposed to projects subjecting them to “a never-ending appeals process.” 

Offshore wind developers said federal regulators desire flexibility around projects’ points of interconnection or turbine designs, changes that can trigger PJM to restart the interconnection process. 

The study also questioned a central premise of the cluster-based interconnection process PJM embarked on this year: that many developers were submitting multiple interconnection requests for the same project to determine which point of interconnection would result in the least expensive network upgrade allocation. Part of the justification for including increasingly large readiness deposits as proposals progress through the queue was to weed out speculative projects. (See FERC Approves PJM Plan to Speed Interconnection Queue.) 

“The extent to which these duplicative requests slow down PJM’s efforts to complete interconnection studies has been hotly debated, and several of PJM’s recent queue reforms were designed to eliminate them,” the study said. “In the sample, only one developer identified an interconnection queue request that had been suspended or paused because it was extremely similar to another project with a separate queue position. Given this issue has been a major theme in PJM discourse, it was surprising to find only a single instance of it among … all the projects in the survey, though it is possible that developers are unwilling to self-report filing a duplicative or speculative interconnection request.” 

PJM spokesperson Jeff Shields disputed the report’s finding that speculative projects did not contribute to the queue backlog, saying there were 734 projects eligible for study when the RTO began implementing the new study approach last year, 118 of which dropped out or did not meet the new readiness requirements. 

He said most of the issues the report laid out are being addressed by the revised process, which has been on pace since implementation began last summer and is expected to clear about 72 GW of generation by mid-2025 and 230 GW over the next three years. The approach is designed to streamline the process for developers and provide more “transparency, certainty and equity,” Shields said in an email. 

“The delays for new projects are related to the fact that there are such a high number of megawatts in the queue ahead of them. What’s more concerning is the 450-plus projects totaling nearly 40,000 MW that have cleared PJM’s study process without moving to construction and operation due to siting, financing and/or supply chain challenges not related to PJM’s process,” he wrote. 

Shields said network upgrade costs should pose minimal barrier for the 26 GW of projects sorted into the expedited process, which places proposals in a fast lane if they’re allocated less than $5 million in upgrades. 

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Stakeholder Soapbox: It’s Time for New Wires on America’s Grid

An overlooked federal goal released alongside the Biden administration’s new power plant emissions standards could have an outsized impact on our power grid. 

The Department of Energy’s goal of upgrading 100,000 miles of existing transmission lines by 2030 comes alongside utility claims that rising demand imperils grid reliability. An existing but underused technology — reconductoring with advanced conductors — can help utilities and grid operators overcome these problems. 

In 2005, Xcel Energy urgently needed to bring more energy into Minneapolis-St. Paul, but the constrained urban environment made building new transmission difficult. Existing transmission lines intersected two major highways, crossed residential and industrial zones, and passed through protected wetlands and a National Wildlife Refuge. Permitting new towers and wires risked delay, extra cost and potential failure. 

Xcel instead decided to replace the existing line with higher-performance wire, increasing transmission capacity along the same route by using the same towers. This “reconductoring” wire replacement process greatly accelerated permitting. After eight weeks of construction, Xcel doubled the line’s ampere rating. 

New research from GridLab and the Goldman School of Public Policy at the University of California, Berkeley is the first estimate of potential clean generation deployment and cost savings that could be unlocked by reconductoring lines with advanced conductors. Replacing standard aluminum conductor steel-reinforced (ACSR) wires with advanced conductors can double a line’s capacity within existing rights of way at typically less than half the price of new line for similar capacity increases. 

Reconductoring is a pathway to spur nearly four times more interzonal transmission capacity expansion by 2035 compared to the average new-build transmission rate. This can help provide the majority of near-term interzonal transmission capacity needs to bring to market the 2,600 GW of cheap clean energy currently clogging interconnection queues. 

Reconductoring can’t meet all the needs of a low-cost clean energy system, but it can buy time to site and develop the new lines needed for long-term needs. Simultaneously reconductoring with advanced conductors and addressing barriers to new greenfield transmission provides the largest savings in total system costs of all considered scenarios: more than $400 billion by 2050 compared to business as usual. 

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The conclusion seems simple: Planning engineers and policymakers should find every place where cost-benefit analysis shows reconductoring with advanced conductor makes sense, then determine how to proceed. Unfortunately, nothing is simple when it comes to the bulk power system. 

A companion report from Energy Innovation and GridLab identifies the barriers that have historically slowed use of advanced conductors and the policy recommendations to add advanced conductors onto the grid as quickly as possible. 

Advanced reconductoring is stuck in the middle when it comes to cost recovery. Because it is a lower capital investment, monopoly utilities are instead incentivized to build entirely new lines. Advanced conductors also cost more than traditional wires, and regulators may view them as an unnecessary expenditure that gold-plates the system. A short-sighted, least-cost planning mindset for transmission owners makes it hard to accurately assess these benefits compared to either building new lines or using conventional conductors, so advanced conductors fall by the wayside. 

New policies at the state and federal level can help ISO/RTOs get the most from this technology. State regulators and legislatures should proactively develop a policy position for advanced conductors, helping expedite planning at the state and ISO/RTO level. For example, RTOs lack the information to second-guess TOs’ determinations that reconductoring with a traditional conductor or greenfield transmission could be done with advanced conductors. State policymakers can also support education and workforce training in reconductoring. 

FERC’s efforts to enhance regional planning processes can significantly improve resilience and integrate low-cost renewables through including advanced conductors. The rule approved by FERC on May 13 aims to modernize these processes by mandating forward-looking planning with a 20-year horizon, making the advantages of advanced conductors — increased transmission capacity and efficiency — more apparent in cost-benefit analyses. As regions update their compliance with this rule, especially in defining which benefits to weigh against costs, FERC can advocate for including conductor efficiency as a key factor in these evaluations. 

Beyond recent rulemakings, FERC should also consider creating independent transmission monitors (ITMs). Many states lack substantial review over transmission planning; in California, for example, 63% of projects from 2019 to 2022 were self-approved as “repair and replacement” projects. Non-RTO regions are not required to produce data allowing stakeholders to study, expose and challenge incumbent utilities to explore reconductoring or other transmission expansion to benefit consumers. ITMs could add data transparency and transmission planning expertise capacity for states and regions to objectively evaluate transmission projects and ensure TOs consider projects that add significant value to customers at lower cost, like reconductoring with advanced conductors. 

America’s grid needs new wires. Advanced reconductoring is ready. Now it’s time to implement the technology. 

Eric Gimon is a senior fellow with Energy Innovation.